Well stimulation operations are designed to increase the production of crude oil and natural gas from wells penetrating subterranean areas containing crude oil, natural gas or both. The key goal of well stimulation is to increase the productivity of a well by removing damage in the vicinity of the wellbore or by superimposing a highly conductive structure onto the subterranean formation. One commonly used stimulation technique is hydraulic fracturing.
Conventional hydraulic fracturing is generally applied by directly treating the ‘pay zone’ of interest, and by using a fracturing fluid that can suspend the proppant until the fracture closes with at least a portion of the proppant in the fracture.
As used herein, “pay zone” is a term used to describe a reservoir formation that contains crude oil and/or natural gas intended to be produced from a wellbore.
The reservoir formations that are typically pay zones include sandstone, limestone, chalk, coal and some types of shale. Pay zones can vary in thickness from less than one foot (0.3048 m) to hundreds of feet (hundreds of m). The permeability of the reservoir formation provides the potential for production.
As used herein, the term “permeability” refers to “the capability of a porous rock or sediment to permit the flow of fluids through its pore spaces”. The term “impermeable”, as used herein, refers to porous substances not permitting the passage of a fluid through the pores interstices”. (The Webster's New Universal Unabridged Dictionary, Barnes and Noble Books, 1996).
The term “effective stress level” refers to the average effective stress level in a formation. The term “higher effective stress” refers to an average effective stress level in a first formation which is greater than the average effective stress level in a second formation. The term “lower effective stress” refers to an average effective stress level in a first formation which is less than the average effective stress level in a second formation. Lower effective stress formations typically, but not always, are permeable formations
Hydraulic fracturing is used to create fractures that extend from the well bore into reservoir formations so as to stimulate the potential for production. A fracturing fluid, typically viscous, is generally injected into the formation with sufficient pressure to create and extend a fracture, and a proppant is used to “prop” or hold open the created fracture after the hydraulic pressure used to generate the fracture has been released. When pumping of the treatment fluid is finished, the fracture “closes”. Loss of fluid to permeable rock results in a reduction in fracture width until the proppant supports the fracture faces.
When fracturing a multi-layered reservoir comprising both permeable and impermeable layers, fluid loss (from the fracture to the reservoir formations) occurs in the permeable layers. When pumping of the treatment fluid is stopped, fluid moves away from the impermeable (typically higher effective stress) layers, and “fluid loss” occurs in the permeable (typically lower effective stress) layers as the pressure declines and the fracture closes. When viscous fluids are used, this fluid movement tends to also carry proppant away from the impermeable (typically higher effective stress) layers. When the fracture closes, the retained fracture conductivity in the impermeable (typically higher effective stress) layers is generally much lower than in the permeable (typically lower effective stress) layers. Consequently, for conventional hydraulic fracturing, if any of the permeable (typically lower effective stress) layers are not in direct contact with the wellbore, the ability for them to flow is restricted by the low fracture conductivity in an impermeable (typically higher effective stress) layer that is in direct contact with the wellbore.
In multi-layered reservoirs it is common for the effective stress in each of the layers to be different. The magnitude of this difference between adjoining layers is dependent upon many factors, including the depositional environment, the burial history, lithology, pore pressure and fluid movement within each of the layers. In many multi-layered reservoirs the impermeable layers have higher effective stresses than the permeable layers. For conventional hydraulic fracturing, with fracture initiation in a lower effective stress layer, fracture height growth tends to be restricted by higher effective stress in layers above or below the lower effective stress layer used for fracture initiation. With higher effective stress layers above and below the zone of injection, fracture growth is favored towards increasing length, rather than increasing height. The contrast in effective stress is used in the design of the fracture treatments, so as to improve the performance of a targeted lower effective stress formation. In order to apply this approach in a multi-layered reservoir, multiple fracture treatments must be performed, each of which targets specific reservoir layers. Such an approach adds both time and cost to the fracturing process.
For multi-layered reservoirs, techniques have been developed that enable fractures to be initiated in each of the reservoir layers and attempt to improve the efficiency of performing multiple fracture treatments. This approach often still requires reservoir layers to be grouped for an individual fracture treatment, due to constraints of cost and/or time for the fracturing process. All of these techniques require the drilling of a vertical, or deviated, well through all of the layers, followed by the stimulation of individual layers or of groupings of layers.
Horizontal, or high angle, wells are generally used to improve production delivery from a reservoir, with each horizontal well being able to replace a number of conventional vertical, or deviated, wells. To obtain high performance, horizontal, or high angle, wells are often steered to follow the reservoir layer that will be produced and are best applied in reservoirs with good vertical permeability (barriers to vertical flow result in lower performance). Consequently, horizontal, or high angle, wells are not usually applied in multi-layer reservoirs (multi-lateral well technology was developed to allow horizontal, or high angle, wells to be placed in more than one reservoir layer).